In the oil and gas industry, geophysical prospecting using seismic surveying techniques are commonly used to aid in the search for and evaluation of subterranean hydrocarbon deposits. A seismic survey represents a well known technique to image or map the subsurface of the earth by sending seismic energy down into the ground and recording the echoes that return after traversing through and reflecting from the subsurface rock layers. The resulting seismic data may be processed to yield information relating to the location of the subsurface reflectors and the physical properties of the subsurface formations.
The source of the down-going seismic energy might be, for example, detonated explosions or seismic vibrators on land, or compressed air released from air guns in marine environments. During a seismic survey, an energy source is placed at various locations near the surface of the earth above a geologic region of interest. Each time the source is activated, it generates a seismic signal that travels downward through the earth, is reflected, and, upon its return, is recorded at many receivers at locations on the surface. Multiple source/recording combinations are then combined to create a near continuous profile of the subsurface that can extend for many miles. Many variations of the conventional source-receiver arrangement are used in practice, for example, VSP (vertical seismic profile) surveys, which are well known in the art. Many different field acquisition geometries and design considerations are well known by those skilled in the art.
A seismic survey is composed of a very large number of individual seismic recordings or traces. In a typical seismic survey, there will usually be several tens of thousands or even millions of traces. A modern seismic trace is a digital recording of the acoustic energy reflected from inhomogeneities or discontinuities in the subsurface, a partial reflection occurring each time there is a sufficient contrast in the elastic properties of the subsurface materials.
Digital samples are usually acquired at 0.002 second (2 millisecond) intervals, although 4 millisecond and 1 millisecond sampling intervals are also common. Each discrete sample in a conventional digital seismic trace is associated with a travel time. In the case of reflected energy, this represents a two-way travel time from the source to the reflector and back up to the surface receiver. Further, the surface location of every trace in a seismic survey is tracked and is made a part of the trace itself during standard data processing (as part of the trace header information). This allows the seismic information contained within the traces to be later correlated with specific surface and subsurface locations, thereby providing a means for posting and contouring seismic data—and attributes extracted therefrom—on a map (i.e., “mapping”).
Seismic data provide a wealth of information for individuals skilled in interpretation to locate potential drilling locations. For example, a processed seismic survey gives a broad view of the structure (topography) of the subsurface rock layers and often reveals important features associated with the entrapment and storage of hydrocarbons such as faults, folds, anticlines, unconformities, salt domes, and reefs, among many others. During the computerized processing of seismic data, estimates of the velocities at which seismic energy is propagated through subsurface rocks are routinely generated and near surface inhomogeneities are detected and displayed. In some cases, seismic waveform attributes of processed data can be used to directly estimate rock porosity, water saturation, and hydrocarbon content. This is particularly true when seismic data are directly correlated to corresponding well log information. Seismic waveform attributes can often be empirically correlated with known hydrocarbon occurrences and these empirical correlations may be extrapolated to seismic data collected over new exploration targets.
Noise energy on seismic records is undesired energy that may be so strong as to interfere with or mask desired signals. Noise may be incoherent or random in nature. Random noise in a land seismic survey includes that due to wind, vehicular, or pedestrian traffic. In marine seismic surveys, random noise includes ship vibrations, surging of the hydrophone cable, flow noise of water around the cable and hydrophones, tugging of the cable by the tail buoy and activity of marine life.
Noise may also be coherent. Assuming that primary reflections from earth strata are the desired signals, coherent noise may comprise refractions, multiple reflections, reflected refractions or refracted reflections, diffractions from point sources on a rugose sea floor or from fault scarps, and coherent noise from mechanical sources such as the regular beating of a ship's screw.
Multiple seismic arrivals (a form of coherent noise), as is well known to those skilled in the art, arise when seismic energy arrives at the surface after being reflected from more than one interface. For example, it is quite common in offshore settings to find that the original seismic signal “bounces” between the surface of the ocean and the ocean bottom a number of times during the seismic recording (FIG. 1A). This results in a repeating waveform that appears at regular time intervals throughout every recorded seismic trace (a “multiple”), the precise time separation being determined by the depth of the water, the velocity of sound in water at the recording location, and the source-receiver offset.
FIG. 1A illustrates various wave paths present in marine acquisition including multiples. Raypath 101 illustrates the path followed by a reflection from the ocean bottom. Ocean bottom reflections are often the strongest energy on seismic records. Raypath 103 illustrates an ocean water bottom multiple. A primary reflection from a rock layer is illustrated by raypath 105. These primary reflections are the data most seismic data processing is directed to enhancing.
Additionally, it is also common to find inter-bed multiples (107 in FIG. 1A) in both land and marine surveys. Inter-bed multiples occur when the seismic signal bounces up and down between rock layer interfaces. The appearance of this multiple arrival energy creates artificial (“ghost”) seismic events that appear as geologic boundaries, but do not represent actual geological boundaries. There is a need for a method to remove these artificial events, while at the same time not removing or altering primary reflections from actual geological boundaries.
Frequency filtering is one method to remove some types of coherent noise. Frequency filtering is effective provided that the frequency spectrum of the noise does not overlap the frequency spectrum of the desired signal. However, coherent noise often exists within the same frequency spectrum as that of the desired signal. Other well-known methods of suppressing coherent noise include spatial filtering, mixing, common offset or common midpoint stacking, vertical or lateral data averaging, array forming and beam steering. Velocity filtering is useful provided the velocity (the normal move-out offset-time correction, dx/dt, known as NMO) of the desired signal is different than that of the apparent velocity of the contaminating noise (FIGS. 1B and 1C). The NMO values of multiples may be similar or indistinguishable from that of the primary desired seismic signal energy.
FIG. 1B illustrates a schematic of where relative seismic energy raypath arrival times will appear on shot records before NMO is applied. The water bottom arrival 101 is the first arrival in time, from NEAR to FAR offsets as labeled from left to right on the top of FIG. 1B. The water bottom multiple is often the next arrival, but since it has slower velocity, it will cross the primary arrival 105 at farther offsets. The water bottom 103 is often much stronger than the primary 105 and will mask the primary arrival signal. The interbed multiple 107 has nearly the same velocity as the primary 105 and can be difficult to distinguish.
FIG. 1C illustrates a schematic of where relative seismic energy raypath arrival times will appear on shot records after NMO is applied. The primary arrival 105 is illustrated by the flat or level reflector. The water bottom arrival 101 is still the first arrival in time, from NEAR to FAR offsets as labeled from left to right on the top of FIG. 1C. The relative reflector relationships remain the same as in FIG. 1B.
One type of seismic attribute analysis that has been given increasing attention in recent years is Amplitude-Variation-with-Offset (“AVO” hereinafter, or sometimes “AVA” Amplitude-Variation-with-Angle-of-incidence) analysis. Broadly speaking, the goal of AVO analysis is to make geologically legitimate offset-dependent reflectivity effects more easily visible. AVO analysis is also relevant to azimuthal-dependent reflectivity effects that may be found in some seismic data sets. The physical principle upon which AVO analyses are based is that the reflection and transmission coefficients at an acoustic impedance boundary are dependent on the angle at which the seismic signal strikes that boundary, and on the contrast in rock properties across the boundary. Thus, from analysing how the amplitude of a reflection varies with angle, one may infer elastic rock properties of the reflector. See the Zoeppritz Equations in Sheriff, R. E., 1991, Encyclopedic Dictionary of Exploration Geophysics: Soc. of Expl. Geophys. Press, 384 pages.
The variation of reflectivity with angle is true of all rock interfaces. The variation in reflectivity is according to the particular properties of the rocks at the reflecting boundary. By way of example, a sandstone with gas in its pore spaces would have different angle-dependent variations in reflection- and transmission-coefficients as the same sandstone with water in the pore spaces. Reflection and transmission coefficients are also different for different rock types, (such as limestone as compared with sandstone, for example). Thus, by examining variations in seismic amplitude versus incidence angle (or an equivalent spatial component, for example shot-receiver offset) it is sometimes possible to make inferences about the subsurface lithology and fluid content of a particular reflector that could not otherwise be obtained.
These effects can sometimes be identified visually by arranging the move-out corrected seismic traces from a single gather or from a composite of more than one conventional acquisition gather. The traces of the seismic gathers are sorted in order of increasing source-to-receiver offset. The amplitudes of a reflection at the near traces are compared with the amplitudes on more distant traces at the same reflection time. (See, for example, page 25 of “AVO Analysis: Tutorial & Review”, by J. Castagna, appearing in Offset-Dependent Reflectivity—Theory and Practice of AVO Analysis, John Castagna and Milo Backus (editors), SEG Press, pp. 3-36, 1993, the disclosure of which is incorporated herein by reference). Alternatively, various quantitative AVO attributes may be calculated from the gather. By combining many of these attributes, entire sections or volumes may be formed that represent AVO effects.
AVO analysis involves fitting a parametric curve (i.e., a function characterized by one or more constant coefficients, usually of some form of the Zoeppritz Equations) to seismic amplitudes of a seismic gather. Often, the typical parametric representation is used to model and account for compressional or “P” type reflections in the seismic data. When other seismic propagation modes are present, the fitted curve may fail to adequately model the seismic data, which might potentially lead to false or masked hydrocarbon indicators.
By way of explanation, elastic seismic energy propagates through the earth in one of two modes: compressional or “P” waves and shear or “S” waves, either of which might be generated by a wide variety of seismic sources. “Converted waves” are those waves that travel first as one type of wave and then are converted to the other, the conversion between wave-types happening at any seismic discontinuity. “Primary” reflections are P-mode waves that are reflected only once from a subsurface rock interface. Multi-path reflections are reflected more than once.
In conventional AVO analysis, these converted and multi-path reflections are regarded as coherent noise and so are attenuated—to the extent possible—during pre-processing prior to AVO analysis. However, this attenuation is imperfect and invariably at least some energy from the unwanted modes is not successfully attenuated. This unwanted, unattenuated noise energy has the potential to mask the desired signal and even create false signals that appear valid. Additionally, these modes can cause misinterpretations of the recorded seismic data and could lead to imperfect model of the subsurface.
Heretofore, as is well known in the seismic processing and seismic interpretation arts, there has been a need for a method and apparatus for identifying and extracting or suppressing unwanted noise energy from the traces in a seismic survey. Additionally, this method and apparatus should provide for improved attribute analyses and interpretation of seismic data. Accordingly, it should now be recognized, as was recognized by the present inventors, that there exists a need for a method and apparatus of seismic data processing to address and solve the above-described problems.
Before proceeding to a description of the present invention, however, it should be noted and remembered that the description of the invention which follows, together with the accompanying drawings, should not be construed as limiting the invention to the examples (or embodiments) shown and described. This is so because those skilled in the art to which the invention pertains will be able to devise other forms of this invention within the ambit of the appended claims.